LabNotes - May 2011
Materials for Oxy-fuel Combustion
Materials research is underway at NETL to enable the development of advanced combustion technologies that can capture at least 90% of a power plant's carbon dioxide (CO2) emissions with less than a 35% increase in the cost of electricity. Oxy-fuel combustion is a new technology that is based on burning fossil fuels in a mixture of recirculated flue gas and oxygen, rather than in air. An optimized oxy-combustion power plant will have ultra-low emissions since the flue gas that results from oxy-fuel combustion is almost all CO2 and water vapor. Once the water vapor is condensed out of the portion of the flue gas that is not being recirculated, it is relatively easy to sequester the CO2 so that it doesn't escape into the atmosphere. NETL and several partners are already developing oxy-combustion coal-burning power plants, with large-scale tests underway. Because of oxy-combustion's higher heat output, boilers - conventionally designed to burn coal with air - have to be made out of materials that can withstand higher temperatures.
NETL is also conducting research on ways to retrofit existing power plants to incorporate the advantages of oxy-fuel combustion. Most schemes to accommodate these changes in heating behavior involve circulating a fraction of the CO2-rich flue gas back into the boiler, where it takes the place of nitrogen, diluting the oxygen concentration to an appropriate level. If this split occurs before flue gas desulfurization (FGD), then the boiler has to operate with much higher sulfur (and perhaps chloride) levels, which introduces corrosion concerns. If recirculation is done after FGD, then there will be a large efficiency loss, but sulfur levels will be relatively low.
Figure 1 is a representative pulverized coal (pc) boiler refitted for oxy-firing. Relevant materials performance research areas at NETL are circled. In brief, they are fireside corrosion within the boiler, steam turbine oxidation, supercritical CO2 pipeline corrosion, and corrosion involved in an NETL-developed method of capturing CO2 - Integrated Pollutant Removal (IPR®). Materials research related to fireside corrosion within the boiler and corrosion during IPR are discussed below.
Figure 1. A representative pc boiler refitted for oxy-firing. The materials performance research areas at NETL are circled. Note the two different options for CO2 circulation back into the boiler to maintain heat transfer characteristics similar to air-firing.
Fireside Boiler Corrosion
Laboratory tests comparing air-firing to oxy-firing conditions were conducted at temperatures expected to result in the highest fireside corrosion rates (675-700 °C). Depending on the CO2 circulation path, sulfur levels will be elevated in both the gas and ash phases. Higher sulfur levels are expected to increase corrosion rates and thus may require more corrosion resistant alloys or coatings in an oxy-fired boiler than in an air-fired boiler. Figure 2 shows elemental map microstructures for a boiler steel alloy (T92) exposed to various environments (without coal ash, and with two levels of sulfate within a coal ash cover) for 250 hours. In general, corrosion resistance (and cost) increases with increasing Cr in the alloy.
Figure 2. Color-enhanced elemental maps of a boiler steel (grade T92), which contains a moderate level (9%) of chromium, exposed in oxy- and air- firing environments, with and without a covering ash. The original metal surface is indicated by the dotted line. Outer scales are pure Fe oxide (with embedded ash when ash was present). Inner scales are mixtures of layered Fe and Cr oxides and sulfides. Increased sulfur in the coal ash proved to be more important to fireside corrosion than increased sulfur in the gas phase.
For the exposures shown in Fig. 2, thicker scales (meaning more corrosion) are associated with more sulfur in the ash rather than in the gas phase. The layering within the inner scale shows successive instances where a somewhat protective chromia-rich oxide layer has become less protective and broken away from the metal.
This fireside boiler corrosion research was part of the U.S. contribution to the US-UK collaboration on advanced materials for clean coal technology supported by the UK Department of Energy and Climate Change (DECC) and the U.S. Department of Energy (DOE). Among the results arising from the collaboration is that corrosion sensors could be used within the boiler to monitor corrosion semi-quantitatively.
Oxide Solubility in Coal Ash
Fireside corrosion within an oxy-fuel combustion boiler is typically most severe at temperatures from 675 to 700 °C. This temperature range is associated with the presence of molten ash phases. Below these temperatures, the phases are solid; above these temperatures, these phases decompose into solid constituent phases. Protective metal oxides (Fe and Cr oxides) can dissolve in these molten ash phases. This is termed ‘hot corrosion’. In cases where the solubility within the molten phase decreases with distance away from the alloy (due to temperature and gas activities not being constant within the ash), then the oxides will precipitate out in a non-protective manner and lead to rapid metal corrosion. Figure 3 shows T92 steel after exposure in air-fired conditions.
Figure 3. T92 exposed in air-fired conditions at 675 °C. From left to right are the metal, scale, and ash. This backscattered electron microscope image shows elemental contrast. Relatively heavy elements such as Fe and Cr are brighter; relatively light elements such as O and S and most elements in the ash are darker. The image shows large amounts of metal within the ash that originated in the alloy, oxidized to form the scale, dissolved at the scale-ash interface, and then came out of solution within the ash.
Research is ongoing to determine chromia (Cr2O3) solubility in synthetic ashes as a function of the amount of SO2 in the gas phase. If the method proves successful, then ash from a variety of oxy-firing burner rigs, burning a variety of coals, can be tested for their corrosivity.
Integrated Pollution Removal Corrosion
NETL developed the Integrated Pollutant Removal (IPR®) process--a flue gas clean-up and heat recovery process that can be applied to fossil-fueled power plants. Oxy-fuel combustion of coal generates combustion gas that is predominantly CO2 and H2O. It has much less N2 than is found with air-firing. In IPR, the combustion gas is compressed in stages. Interstage cooling transfers heat to the boiler feedwater system while condensing water from the gas. Thus, the flue-gas is dried and cleaned as it is compressed, resulting in a CO2-rich sequestration-ready supercritical mixture. Mercury and sulfur compounds (along with other trace materials) report to the CO2 product or to the condensed water, according to the reagents employed and manner in which IPR is operated. Heat recovery during IPR has the potential to improve thermal efficiency in existing plants retrofitted with oxy-combustion. A schematic of the overall process is shown in Fig. 4. Most of the various stages involve either compression or heat recovery.
Figure 4. Multiple-technique electrochemical corrosion monitoring technology is to be used to collect information on corrosion rates and susceptibility to pitting during Integrated Pollutant Removal (IPR®). In IPR, flue gases (FGR tap) pass through the system from left to right, with acid gas removal through pH control in TWR, losing heat in HX heat exchangers, and increasing in pressure in STGX compressors until CAPTURE. Condensed water is collected (VX) and treated. Red symbols signify corrosion probe locations.
Throughout the IPR process, the combustion gas is fractionated into liquid and gas phases to separate CO2 and recover water. Because this approach could establish conditions that are quite corrosive, more corrosion-resistant alloys may be required, although it may be possible to make lower temperature components with corrosion-resistant polymers.
A field trial of the IPR system is underway and will incorporate electrochemical corrosion monitoring at various locations, as shown in Fig. 4. These tests will allow real-time corrosion monitoring to take place, including measurement of corrosion rates and susceptibility to pitting. Two materials will be tested within the system - 316 stainless steel (typically used in process piping and tubing) and nickel base alloy 625 (a candidate alloy with more corrosion resistance).